Athabasca Oil Announces 2025 Second Quarter Results Highlighted by Strong Operational Results, Continued Share Buybacks and a Pristine Financial Position
CALGARY, Alberta, July 24, 2025 (GLOBE NEWSWIRE) — Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) is pleased to report its second quarter results marked by strong operational performance, consistent financial results and execution on return of capital commitments. With low corporate break-evens, differentiated long-life assets and a pristine balance sheet, the Company is well positioned to advance its strategic priorities.
Q2 2025 Consolidated Corporate Results
- Production: Average production of 39,088 boe/d (98% Liquids), representing 4% (15% per share) growth year-over-year.
- Cash Flow: Adjusted Funds Flow of $128 million ($0.25 per share). Cash Flow from Operating Activities of $101 million. Free Cash Flow of $66 million from Athabasca (Thermal Oil).
- Capital Program: $73 million total capital expenditures including $54 million at Leismer to support the 40,000 bbl/d phased growth project.
- Shareholder Returns: Purchased 24 million shares through its buy-back program year-to-date. The Company is committed to returning 100% of Free Cash Flow (Thermal Oil) to shareholders in 2025 and has completed ~$600 million in share buybacks since March 31, 2023, reducing its fully diluted share count by 21%.
Operations Highlights
- Leismer: Production currently ~28,000 bbl/d (June 2025) with four sustaining well pairs expected to be placed on production through the balance of the year. The progressive growth project remains on time and on budget. The Company expects production to stay flat until the next growth plateau of 32,000 bbl/d in H2 2026.
- Hangingstone: Production currently ~8,900 bbl/d (June 2025) following the start-up of two extended reach well pairs which are outperforming management’s expectations. The asset continues to deliver meaningful free cash flow generation.
- Duvernay Energy (“DEC”): A four well pad (30% working interest) with ~5,000 meter laterals was completed in mid July and will be placed on production in August. Completion operations are expected to commence on a three well pad (100% working interest) in September. DEC is positioned for strong operational momentum into year end with an exit target of ~6,000 boe/d.
Resilient Producer
- Pristine Financial Position: The Company has a Net Cash position of $119 million, Liquidity of $437 million (including $304 million cash) and a long-dated maturity of 2029 on its term debt. The Company also has $2.2 billion of tax pools (~80% high-value and immediately deductible).
- Low Break-evens: Long-life, low decline assets afford Athabasca with a sustaining capital advantage. The Company’s 2025 Thermal Oil capital program which includes growth initiatives is fully funded within cash flow below US$50/bbl WTI. Long term sustaining capital investment is estimated at ~C$8/bbl (five‐year annual average) to hold production flat.
2025 Corporate Guidance
- Consolidated Production Outlook: The Company anticipates production at the upper end of guidance of 37,500 – 39,500 boe/d with an exit rate of ~41,000 boe/d. Thermal Oil production is trending at the upper end of its prior guidance of 33,500 – 35,500 bbl/d. Duvernay Energy is expected to average ~4,000 boe/d with an exit target of ~6,000 boe/d following the tie-in of two multi-well pads.
- Thermal Capital: The forecast capital budget for Thermal oil is unchanged at ~$250 million, including sustaining capital and the Leismer expansion project. This $300 million expansion project (over three years) is highly economic (~$25,000/bbl/d capital efficiency) and provides flexibility with interim growth targets to ~32,000 bbl/d in H2 2026 and ~35,000 bbl/d in H1 2027 before achieving the regulatory approved 40,000 bbl/d capacity at the end of 2027. Athabasca’s Thermal Oil capital projects are flexible, highly economic and have phased optionality on timing based on the macroeconomic environment. By year-end 2025, the Company anticipates being ~50% complete of total capital exposure for the expansion project.
- Duvernay Energy Corporation Capital: The 2025 capital program of ~$75 million will drive production momentum in H2 2025. The capital program in DEC is flexible and designed to be self-funded. The Company has a deep inventory of ~444 gross future drilling locations with no near-term land expiries.
- Free Cash Flow Focus: The Company forecasts consolidated Adjusted Funds Flow between $525 – $550 million1, including $475 – $500 million from its Thermal Oil assets. 2025 Thermal Oil Free Cash Flow is forecasted at ~$250 million and is planned to be returned to shareholders through share buybacks. Every +US$1/bbl move in West Texas Intermediate (“WTI”) and Western Canadian Select (“WCS”) heavy oil impacts annual Adjusted Funds Flow by ~$10 million and ~$17 million, respectively.
Corporate Consolidated Strategy
- Value Creation: The Company’s Thermal Oil division provides a differentiated liquids weighted growth platform supported by financial resiliency to execute on return of capital initiatives. Athabasca’s subsidiary company, Duvernay Energy Corporation, is designed to enhance value for Athabasca’s shareholders by providing a clear path for self-funded production and cash flow growth in the Kaybob Duvernay resource play. Athabasca (Thermal Oil) and DEC have independent strategies and capital allocation frameworks.
- Steadfast Focus on Cash Flow Per Share Growth: Athabasca’s disciplined capital allocation framework is designed to unlock shareholder value by prioritizing multi-year cash flow per share growth. The Company forecasts ~20% compounded annual cash flow per share growth between 2025-2029 driven by investing in attractive capital projects and prioritizing share buybacks with 100% of Free Cash Flow. The Company sees significant intrinsic value not reflected in the current share price and intends to remain active with its share buyback strategy.
Athabasca (Thermal Oil) Strategy
- Large Resource Base: Athabasca’s top-tier assets underpin a strong Free Cash Flow outlook with low sustaining capital requirements. The long life, low decline asset base includes ~1.2 billion barrels of Proved plus Probable reserves and ~1 billion barrels of Contingent Resource.
- Strong Financial Position: Prudent balance sheet management is a core tenet of Athabasca’s strategy. The Company has a Net Cash position of $119 million, Liquidity of $437 million (including $304 million cash) and a long-dated maturity of 2029 on its term debt.
- Leismer Progressive Growth: This $300 million expansion project (over three years) is highly economic (~$25,000/bbl/d capital efficiency) and provides flexibility with interim growth targets to ~32,000 bbl/d in H2 2026 and ~35,000 bbl/d in H1 2027 before achieving the regulatory approved 40,000 bbl/d capacity at the end of 2027. On completion of the expansion project, the Company can maintain Leismer at 40,000 bbl/d for approximately fifty years (Proved plus Probable Reserves).
- Sustaining Hangingstone: The Hangingstone asset is very competitive and continues to deliver meaningful cash flow contributions to the Company. The objective is to sustain production and maintain competitive netbacks ($36.51/bbl H1 2025 Operating Netback).
- Corner – Future Optionality: The Company’s Corner asset is a large de-risked oil sands asset adjacent to Leismer with 351 million barrels of Proved plus Probable reserves and 520 million barrels Contingent Resource (Best Estimate Unrisked). There are over 300 delineation wells and ~80% seismic coverage, with reservoir qualities similar to or better than Leismer. The asset has a 40,000 bbl/d regulatory approval for development with the existing pipeline corridor passing through the Corner lease. The Company has updated its development plans and is finalizing facility cost estimates, with a focus on capital efficient modular design.
- Significant Multi-Year Free Cash Flow: Inclusive of the progressive growth at Leismer, Athabasca (Thermal Oil) expects to generate in excess of $1.8 billion of Free Cash Flow1 during the five-year time frame of 2025-29. Free Cash Flow will continue to support the Company’s return of capital initiatives.
- Sound Heavy Oil Fundamentals: Canadian heavy oil markets remain strong supported by the Trans Mountain Expansion pipeline and sustained global refining demand. This has resulted in tighter and less volatile WCS heavy differentials with August index pricing at ~US$10/bbl. Athabasca is a direct beneficiary of structurally tighter differentials that are forecasted to hold in the coming years.
- Thermal Oil Royalty Advantage: Athabasca has significant unrecovered capital balances on its Thermal Oil Assets that ensure a low Crown royalty framework (~6%1). Leismer is forecasted to remain pre-payout until late 20271 and Hangingstone is forecasted to remain pre-payout beyond 20301.
- Tax Free Horizon Advantage: Athabasca (Thermal Oil) has $2.2 billion of valuable tax pools and does not forecast paying cash taxes this decade.
Duvernay Energy Strategy
- Accelerating Value: DEC is an operated, private subsidiary of Athabasca (owned 70% by Athabasca and 30% by Cenovus Energy). DEC accelerates value realization for Athabasca’s shareholders by providing a clear path for self-funded production and cash flow growth without compromising Athabasca’s capacity to fund its Thermal Oil assets or its return of capital strategy.
- Kaybob Duvernay Focused: Exposure to ~200,000 gross acres in the liquids rich and oil windows with ~444 gross future well locations, including ~46,000 gross acres with 100% working interest.
- Self-Funded Growth: Near-term activity will be funded within Adjusted Funds Flow, initial seed capital and the DEC credit facility. The Company has growth potential to in excess of ~20,000 boe/d (75% Liquids) by the late 2020s1.
Footnote: Refer to the “Reader Advisory” section within this news release for additional information on Non‐GAAP Financial Measures (e.g. Adjusted Funds Flow, Free Cash Flow, Net Cash, Liquidity) and production disclosure.
1 Pricing assumptions: H1 2025 actualized and US$65 WTI, US$12.50 WCS heavy differential, C$2 AECO, and 0.725 C$/US$ FX for H2 2025. 2026+ US$70 WTI, US$12.50 WCS heavy differential, C$3 AECO, and 0.725 C$/US$ FX
Financial and Operational Highlights
| Three months ended June 30, | Six months ended June 30, | |||||||||||||||
| ($ Thousands, unless otherwise noted) | 2025 | 2024 | 2025 | 2024 | ||||||||||||
| CORPORATE CONSOLIDATED(1) | ||||||||||||||||
| Petroleum and natural gas production (boe/d)(2) | 39,088 | 37,621 | 38,404 | 35,546 | ||||||||||||
| Petroleum, natural gas and midstream sales | $ | 360,070 | $ | 401,738 | $ | 727,914 | $ | 712,854 | ||||||||
| Operating Income(2) | $ | 141,707 | $ | 179,751 | $ | 287,297 | $ | 284,886 | ||||||||
| Operating Income Net of Realized Hedging(2)(3) | $ | 142,101 | $ | 178,176 | $ | 286,048 | $ | 284,756 | ||||||||
| Operating Netback ($/boe)(2) | $ | 38.81 | $ | 52.46 | $ | 41.30 | $ | 44.77 | ||||||||
| Operating Netback Net of Realized Hedging ($/boe)(2)(3) | $ | 38.92 | $ | 52.00 | $ | 41.12 | $ | 44.75 | ||||||||
| Capital expenditures | $ | 73,066 | $ | 48,453 | $ | 136,399 | $ | 124,464 | ||||||||
| Cash flow from operating activities | $ | 101,432 | $ | 135,083 | $ | 224,785 | $ | 211,721 | ||||||||
| per share – basic | $ | 0.20 | $ | 0.24 | $ | 0.44 | $ | 0.38 | ||||||||
| Adjusted Funds Flow(2) | $ | 127,591 | $ | 165,746 | $ | 257,266 | $ | 253,518 | ||||||||
| per share – basic | $ | 0.25 | $ | 0.30 | $ | 0.51 | $ | 0.45 | ||||||||
| ATHABASCA (THERMAL OIL) | ||||||||||||||||
| Bitumen production (bbl/d)(2) | 36,476 | 33,765 | 35,613 | 32,651 | ||||||||||||
| Petroleum, natural gas and midstream sales | $ | 355,160 | $ | 395,279 | $ | 717,535 | $ | 700,320 | ||||||||
| Operating Income(2) | $ | 135,803 | $ | 161,694 | $ | 271,119 | $ | 262,143 | ||||||||
| Operating Netback ($/bbl)(2) | $ | 39.79 | $ | 52.59 | $ | 42.02 | $ | 44.91 | ||||||||
| Capital expenditures | $ | 56,110 | $ | 34,084 | $ | 106,486 | $ | 76,203 | ||||||||
| Adjusted Funds Flow(2) | $ | 122,097 | $ | 149,413 | $ | 243,450 | $ | 233,126 | ||||||||
| Free Cash Flow(2) | $ | 65,987 | $ | 115,329 | $ | 136,964 | $ | 156,923 | ||||||||
| DUVERNAY ENERGY(1) | ||||||||||||||||
| Petroleum and natural gas production (boe/d)(2) | 2,612 | 3,856 | 2,791 | 2,895 | ||||||||||||
| Percentage Liquids (%)(2) | 72 | % | 80 | % | 73 | % | 77 | % | ||||||||
| Petroleum, natural gas and midstream sales | $ | 13,526 | $ | 26,749 | $ | 31,145 | $ | 38,287 | ||||||||
| Operating Income(2) | $ | 5,904 | $ | 18,057 | $ | 16,178 | $ | 22,743 | ||||||||
| Operating Netback ($/boe)(2) | $ | 24.84 | $ | 51.46 | $ | 32.03 | $ | 43.17 | ||||||||
| Capital expenditures | $ | 16,956 | $ | 14,369 | $ | 29,913 | $ | 48,261 | ||||||||
| Adjusted Funds Flow(2) | $ | 5,494 | $ | 16,333 | $ | 13,816 | $ | 20,392 | ||||||||
| Free Cash Flow(2) | $ | (11,462 | ) | $ | 1,964 | $ | (16,097 | ) | $ | (27,869 | ) | |||||
| NET INCOME AND COMPREHENSIVE INCOME | ||||||||||||||||
| Net income and comprehensive income(4) | $ | 56,870 | $ | 96,076 | $ | 128,874 | $ | 134,685 | ||||||||
| per share – basic(4) | $ | 0.11 | $ | 0.17 | $ | 0.25 | $ | 0.24 | ||||||||
| per share – diluted(4) | $ | 0.11 | $ | 0.17 | $ | 0.25 | $ | 0.24 | ||||||||
| COMMON SHARES OUTSTANDING | ||||||||||||||||
| Weighted average shares outstanding – basic | 502,593,860 | 557,299,962 | 508,393,229 | 562,188,451 | ||||||||||||
| Weighted average shares outstanding – diluted | 510,591,132 | 566,559,671 | 512,076,328 | 569,058,329 | ||||||||||||
| June 30, | December 31, | |||||
| As at ($ Thousands) | 2025 | 2024 | ||||
| LIQUIDITY AND BALANCE SHEET (CONSOLIDATED) | ||||||
| Cash and cash equivalents | $ | 304,048 | $ | 344,836 | ||
| Available credit facilities(5) | $ | 133,074 | $ | 136,324 | ||
| Face value of term debt | $ | 200,000 | $ | 200,000 | ||
| (1) Corporate Consolidated and Duvernay Energy reflect gross production and financial metrics before taking into consideration Athabasca’s 70% equity interest in Duvernay Energy. | ||||||
| (2) Refer to the “Reader Advisory” section within this News Release for additional information on Non-GAAP Financial Measures and production disclosure. | ||||||
| (3) Includes realized commodity risk management gain of $0.4 million and loss of $1.2 million for the three and six months ended June 30, 2025 (three and six months ended June 30, 2024 – loss of $1.6 million and $0.1 million). | ||||||
| (4) Net income and comprehensive income per share amounts are based on net income and comprehensive income attributable to shareholders of the Parent Company. In the calculation of diluted net income per share for the three months ended June 30, 2025 net income was increased by $0.4 million, to account for the impact to net income had the outstanding warrants been converted to equity. In the calculation of diluted net income per share for the three months ended June 30, 2024 net income was reduced by $0.4 million, to account for the impact to net income had the outstanding warrants been converted to equity. | ||||||
| (5) Includes available credit under Athabasca’s and Duvernay Energy’s Credit Facilities and Athabasca’s Unsecured Letter of Credit Facility. | ||||||
Athabasca (Thermal Oil) Q2 2025 Highlights and Operations Update
- Production: Production of 36,476 bbl/d (27,818 bbl/d at Leismer and 8,658 bbl/d at Hangingstone).
- Cash Flow: Adjusted Funds Flow of $122.1 million; Operating Income of $135.8 million with an Operating Netback of $39.79/bbl ($42.02/bbl H1 2025).
- Capital: $56.1 million of capital expenditures in Q2, with $53.9 million at Leismer as the Company advances the 40,000 bbl/d progressive growth project.
- Free Cash Flow: $66.0 million of Free Cash Flow supporting return of capital commitment.
Leismer
Earlier this year, the Company brought six extended reach redrills on Pad L1 (1,000 – 1,700 meter laterals) on production supporting current production of ~28,000 bbl/d (June 2025). Four well pairs on Pad L10 are expected to maintain production rates at facility capacity for the balance of 2025. The first two wells started steaming in April with production expected in Q3, and the final two will begin steaming this summer with first production expected in Q4. Another six well pairs will be drilled on Pad 11 in H2 2025.
Activity at Leismer remains focused on advancing progressive growth to 40,000 bbl/d by the end of 2027. The project cost is estimated at $300 million generating a capital efficiency of approximately $25,000/bbl/d. The $300 million will be spent between 2025 and 2027 and includes an estimated $190 million for facility capital and an estimated $110 million for growth wells. By year-end 2025, the Company anticipates being ~50% complete of total capital exposure for the expansion project. The project remains on budget and on schedule with the original sanction plans announced in July 2024. The progressive build provides flexibility with interim growth targets to ~32,000 bbl/d in H2 2026 following the next planned turnaround, and ~35,000 bbl/d in H1 2027 before achieving the regulatory approved 40,000 bbl/d capacity at the end of 2027.
Hangingstone
At Hangingstone, two extended reach sustaining well pairs (~1,400 meter average laterals) were placed on production in March with production of ~8,900 bbl/d (June 2025). The well pairs ramped up faster than anticipated, benefiting from favorable reservoir temperatures and pressure supported by offsetting wells. Current well pair performance between 800 – 1,000 bbl/d per well has exceeded management’s expectations. Hangingstone continues to deliver meaningful cash flow contributions to the Company.
Duvernay Energy Corporation Q2 2025 Highlights and Operations Update
- Production: Production of 2,612 boe/d (72% Liquids).
- Cash Flow: Adjusted Funds Flow of $5.5 million with an Operating Netback of $24.84/boe ($32.03/boe H1 2025).
- Capital: $17.0 million of capital expenditures including completions on a 30% working interest four-well pad.
During the quarter completions operations commenced on a four well pad (30% working interest) with average laterals of ~5,000 meters. Completion operations on this pad were completed in mid July and the wells are expected to be on production in early August. A three well pad (100% working interest) is scheduled to be completed in early Fall and on production shortly thereafter. Earlier in 2025, a strategic gathering system was completed connecting the operated wells to existing operated infrastructure.
Production from new wells drilled in 2024 continue to validate DEC’s type curve expectations. The five wells placed on production have averaged IP30’s of ~1,200 boe/d per well (86% Liquids) and IP90s of ~940 boe/d (86% Liquids) per well.
DEC retains significant operational flexibility with no near-term land expiries and the ability to adjust spending in response to commodity price movements.
About Athabasca Oil Corporation
Athabasca Oil Corporation is a Canadian energy company with a focused strategy on the development of thermal and light oil assets. Situated in Alberta’s Western Canadian Sedimentary Basin, the Company has amassed a significant land base of extensive, high quality resources. Athabasca’s light oil assets are held in a private subsidiary (Duvernay Energy Corporation) in which Athabasca owns a 70% equity interest. Athabasca’s common shares trade on the TSX under the symbol “ATH”. For more information, visit www.atha.com.
For more information, please contact:
| Matthew Taylor | Robert Broen |
| Chief Financial Officer | President and CEO |
| 1-403-817-9104 | 1-403-817-9190 |
| mtaylor@atha.com | rbroen@atha.com |
Reader Advisory:
This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward-looking information. The use of any of the words “anticipate”, “plan”, “project”, “continue”, “maintain”, “may”, “estimate”, “expect”, “will”, “target”, “forecast”, “could”, “intend”, “potential”, “guidance”, “outlook” and similar expressions suggesting future outcome are intended to identify forward-looking information. The forward-looking information is not historical fact, but rather is based on the Company’s current plans, objectives, goals, strategies, estimates, assumptions and projections about the Company’s industry, business and future operating and financial results. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. No assurance can be given that these expectations will prove to be correct and such forward-looking information included in this News Release should not be unduly relied upon. This information speaks only as of the date of this News Release. In particular, this News Release contains forward-looking information pertaining to, but not limited to, the following: our strategic plans; the allocation of future capital; timing and quantum for shareholder returns including share buybacks; the terms of our NCIB program; our drilling plans and capital efficiencies; production growth to expected production rates and estimated sustaining capital amounts; timing of Leismer’s and Hangingstone’s pre-payout royalty status; applicability of tax pools; Adjusted Funds Flow and Free Cash Flow over various periods; type well economic metrics; number of drilling locations; forecasted daily production and the composition of production; break-even metrics, our outlook in respect of the Company’s business environment, including in respect of commodity pricing; and other matters.
In addition, information and statements in this News Release relating to “Reserves” and “Resources” are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and that the reserves and resources described can be profitably produced in the future. With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: commodity prices; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct business and the effects that such regulatory framework will have on the Company, including on the Company’s financial condition and results of operations; the Company’s financial and operational flexibility; the Company’s financial sustainability; Athabasca’s cash flow break-even commodity price; the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the applicability of technologies for the recovery and production of the Company’s reserves and resources; future capital expenditures to be made by the Company; future sources of funding for the Company’s capital programs; the Company’s future debt levels; future production levels; the Company’s ability to obtain financing and/or enter into joint venture arrangements, on acceptable terms; operating costs; compliance of counterparties with the terms of contractual arrangements; impact of increasing competition globally; collection risk of outstanding accounts receivable from third parties; geological and engineering estimates in respect of the Company’s reserves and resources; recoverability of reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities and the quality of its assets. Certain other assumptions related to the Company’s Reserves and Resources are contained in the report of McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluating Athabasca’s Proved Reserves, Probable Reserves and Contingent Resources as at December 31, 2024 (which is respectively referred to herein as the “McDaniel Report”).
Actual results could differ materially from those anticipated in this forward-looking information as a result of the risk factors set forth in the Company’s Annual Information Form (“AIF”) dated March 5, 2025 available on SEDAR at www.sedarplus.ca, including, but not limited to: weakness in the oil and gas industry; exploration, development and production risks; prices, markets and marketing; market conditions; trade relations and tariffs; climate change and carbon pricing risk; statutes and regulations regarding the environment including deceptive marketing provisions; regulatory environment and changes in applicable law; gathering and processing facilities, pipeline systems and rail; reputation and public perception of the oil and gas sector; environment, social and governance goals; political uncertainty; state of capital markets; ability to finance capital requirements; access to capital and insurance; abandonment and reclamation costs; changing demand for oil and natural gas products; anticipated benefits of acquisitions and dispositions; royalty regimes; foreign exchange rates and interest rates; reserves; hedging; operational dependence; operating costs; project risks; supply chain disruption; financial assurances; diluent supply; third party credit risk; indigenous claims; reliance on key personnel and operators; income tax; cybersecurity; advanced technologies; hydraulic fracturing; liability management; seasonality and weather conditions; unexpected events; internal controls; limitations and insurance; litigation; natural gas overlying bitumen resources; competition; chain of title and expiration of licenses and leases; breaches of confidentiality; new industry related activities or new geographical areas; water use restrictions and/or limited access to water; relationship with Duvernay Energy Corporation; management estimates and assumptions; third-party claims; conflicts of interest; inflation and cost management; credit ratings; growth management; impact of pandemics; ability of investors resident in the United States to enforce civil remedies in Canada; and risks related to our debt and securities. All subsequent forward-looking information, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements.
Also included in this News Release are estimates of Athabasca’s 2025 outlook which are based on the various assumptions as to production levels, commodity prices, currency exchange rates and other assumptions disclosed in this News Release. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Athabasca and is included to provide readers with an understanding of the Company’s outlook. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The outlook and forward-looking information contained in this New Release was made as of the date of this News release and the Company disclaims any intention or obligations to update or revise such outlook and/or forward-looking information, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.
Oil and Gas Information
“BOEs” may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Initial Production Rates
Test Results and Initial Production Rates: The well test results and initial production rates provided herein should be considered to be preliminary, except as otherwise indicated. Test results and initial production rates disclosed herein may not necessarily be indicative of long-term performance or of ultimate recovery.
Reserves Information
The McDaniel Report was prepared using the assumptions and methodology guidelines outlined in the COGE Handbook and in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities, effective December 31, 2024. There are numerous uncertainties inherent in estimating quantities of bitumen, light crude oil and medium crude oil, tight oil, conventional natural gas, shale gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. Reserves figures described herein have been rounded to the nearest MMbbl or MMboe. For additional information regarding the consolidated reserves and information concerning the resources of the Company as evaluated by McDaniel in the McDaniel Report, please refer to the Company’s AIF.
Reserve Values (i.e. Net Asset Value) is calculated using the estimated net present value of all future net revenue from our reserves, before income taxes discounted at 10%, as estimated by McDaniel effective December 31, 2024 and based on average pricing of McDaniel, Sproule and GLJ as of January 1, 2025.
The 444 gross Duvernay drilling locations referenced include: 87 proved undeveloped locations and 85 probable undeveloped locations for a total of 172 booked locations with the balance being unbooked locations. Proved undeveloped locations and probable undeveloped locations are booked and derived from the Company’s most recent independent reserves evaluation as prepared by McDaniel as of December 31, 2024 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal management estimates. Unbooked locations do not have attributed reserves or resources (including contingent or prospective). Unbooked locations have been identified by management as an estimation of Athabasca’s multi-year drilling activities expected to occur over the next two decades based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, commodity prices, provincial fiscal and royalty policies, costs, actual drilling results, additional reservoir information that is obtained and other factors.
Non-GAAP and Other Financial Measures, and Production Disclosure
The “Corporate Consolidated Adjusted Funds Flow”, “Corporate Consolidated Adjusted Funds Flow per Share”, “Athabasca (Thermal Oil) Adjusted Funds Flow”, “Duvernay Energy Adjusted Funds Flow”, “Corporate Consolidated Free Cash Flow”, “Athabasca (Thermal Oil) Free Cash Flow”, “Duvernay Energy Free Cash Flow”, “Corporate Consolidated Operating Income”, “Corporate Consolidated Operating Income Net of Realized Hedging”, “Athabasca (Thermal Oil) Operating Income”, “Duvernay Energy Operating Income”, “Corporate Consolidated Operating Netback”, “Corporate Consolidated Operating Netback Net of Realized Hedging”, “Athabasca (Thermal Oil) Operating Netback”, “Duvernay Energy Operating Netback” and “Cash Transportation and Marketing Expense” financial measures contained in this News Release do not have standardized meanings which are prescribed by IFRS and they are considered to be non-GAAP financial measures or ratios. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation with measures that are prepared in accordance with IFRS. Net Cash and Liquidity are supplementary financial measures. The Leismer and Hangingstone operating results are supplementary financial measures that when aggregated, combine to the Athabasca (Thermal Oil) segment results.
Adjusted Funds Flow, Adjusted Funds Flow Per Share and Free Cash Flow
Adjusted Funds Flow and Free Cash Flow are non-GAAP financial measures and are not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. The Adjusted Funds Flow and Free Cash Flow measures allow management and others to evaluate the Company’s ability to fund its capital programs and meet its ongoing financial obligations using cash flow internally generated from ongoing operating related activities. Adjusted Funds Flow per share is a non-GAAP financial ratio calculated as Adjusted Funds Flow divided by the applicable number of weighted average shares outstanding. Adjusted Funds Flow and Free Cash Flow are calculated as follows:
| Three months ended June 30, 2025 | |||||||||
| ($ Thousands) | Athabasca (Thermal Oil) | Duvernay Energy(1) | Corporate Consolidated(1) | ||||||
| Cash flow from operating activities | $ | 101,142 | $ | 290 | $ | 101,432 | |||
| Changes in non-cash working capital | 20,922 | 5,207 | 26,129 | ||||||
| Settlement of provisions | 33 | (3 | ) | 30 | |||||
| ADJUSTED FUNDS FLOW | 122,097 | 5,494 | 127,591 | ||||||
| Capital expenditures | (56,110 | ) | (16,956 | ) | (73,066 | ) | |||
| FREE CASH FLOW | $ | 65,987 | $ | (11,462 | ) | $ | 54,525 | ||
| (1) Duvernay Energy and Corporate Consolidated reflect gross financial metrics before taking into consideration Athabasca’s 70% equity interest in Duvernay Energy. | |||||||||
| Six months ended June 30, 2025 | |||||||||
| ($ Thousands) | Athabasca (Thermal Oil) | Duvernay Energy(1) | Corporate Consolidated(1) | ||||||
| Cash flow from operating activities | $ | 214,569 | $ | 10,216 | $ | 224,785 | |||
| Changes in non-cash working capital | 28,152 | 3,595 | 31,747 | ||||||
| Settlement of provisions | 729 | 5 | 734 | ||||||
| ADJUSTED FUNDS FLOW | 243,450 | 13,816 | 257,266 | ||||||
| Capital expenditures | (106,486 | ) | (29,913 | ) | (136,399 | ) | |||
| FREE CASH FLOW | $ | 136,964 | $ | (16,097 | ) | $ | 120,867 | ||
| (1) Duvernay Energy and Corporate Consolidated reflect gross financial metrics before taking into consideration Athabasca’s 70% equity interest in Duvernay Energy. | |||||||||
| Three months ended June 30, 2024 | |||||||||
| ($ Thousands) | Athabasca (Thermal Oil) | Duvernay Energy(1) | Corporate Consolidated(1) | ||||||
| Cash flow from operating activities | $ | 124,027 | $ | 11,056 | $ | 135,083 | |||
| Changes in non-cash working capital | 25,375 | 5,390 | 30,765 | ||||||
| Settlement of provisions | 11 | (113 | ) | (102 | ) | ||||
| ADJUSTED FUNDS FLOW | 149,413 | 16,333 | 165,746 | ||||||
| Capital expenditures | (34,084 | ) | (14,369 | ) | (48,453 | ) | |||
| FREE CASH FLOW | $ | 115,329 | $ | 1,964 | $ | 117,293 | |||
| (1) Duvernay Energy and Corporate Consolidated reflect gross financial metrics before taking into consideration Athabasca’s 70% equity interest in Duvernay Energy. | |||||||||
| Six months ended June 30, 2024 | |||||||||
| ($ Thousands) | Athabasca (Thermal Oil) | Duvernay Energy(1) | Corporate Consolidated(1) | ||||||
| Cash flow from operating activities | $ | 197,068 | $ | 14,653 | $ | 211,721 | |||
| Changes in non-cash working capital | 34,761 | 5,535 | 40,296 | ||||||
| Settlement of provisions | 1,297 | 204 | 1,501 | ||||||
| ADJUSTED FUNDS FLOW | 233,126 | 20,392 | 253,518 | ||||||
| Capital expenditures | (76,203 | ) | (48,261 | ) | (124,464 | ) | |||
| FREE CASH FLOW | $ | 156,923 | $ | (27,869 | ) | $ | 129,054 | ||
| (1) Duvernay Energy and Corporate Consolidated reflect gross financial metrics before taking into consideration Athabasca’s 70% equity interest in Duvernay Energy. | |||||||||
Duvernay Energy Operating Income and Operating Netback
The non-GAAP measure Duvernay Energy Operating Income in this News Release is calculated by subtracting the Duvernay Energy royalties, operating expenses and transportation & marketing expenses from petroleum and natural gas sales which is the most directly comparable GAAP measure. The Duvernay Energy Operating Netback per boe is a non-GAAP financial ratio calculated by dividing the Duvernay Energy Operating Income by the Duvernay Energy production. The Duvernay Energy Operating Income and the Duvernay Energy Operating Netback measures allow management and others to evaluate the production results from the Company’s Duvernay Energy assets.
The Duvernay Energy Operating Income is calculated using the Duvernay Energy Segments GAAP results, as follows:
| Three months ended June 30, | Six months ended June 30, | |||||||||||
| ($ Thousands, unless otherwise noted) | 2025 | 2024 | 2025 | 2024 | ||||||||
| Petroleum and natural gas sales | $ | 13,526 | $ | 26,749 | $ | 31,145 | $ | 38,287 | ||||
| Royalties | (1,792 | ) | (3,498 | ) | (4,553 | ) | (5,812 | ) | ||||
| Operating expenses | (4,870 | ) | (4,063 | ) | (8,656 | ) | (7,703 | ) | ||||
| Transportation and marketing | (960 | ) | (1,131 | ) | (1,758 | ) | (2,029 | ) | ||||
| DUVERNAY ENERGY OPERATING INCOME | $ | 5,904 | $ | 18,057 | $ | 16,178 | $ | 22,743 | ||||
Athabasca (Thermal Oil) Operating Income and Operating Netback
The non-GAAP measure Athabasca (Thermal Oil) Operating Income in this News Release is calculated by subtracting the Athabasca (Thermal Oil) segments cost of diluent blending, royalties, operating expenses and cash transportation & marketing expenses from heavy oil (blended bitumen) and midstream sales which is the most directly comparable GAAP measure. The Athabasca (Thermal Oil) Operating Netback per bbl is a non-GAAP financial ratio calculated by dividing the respective projects Operating Income by its respective bitumen sales volumes. The Athabasca (Thermal Oil) Operating Income and the Athabasca (Thermal Oil) Operating Netback measures allow management and others to evaluate the production results from the Athabasca (Thermal Oil) assets.
The Athabasca (Thermal Oil) Operating Income is calculated using the Athabasca (Thermal Oil) Segments GAAP results, as follows:
| Three months ended June 30, | Six months ended June 30, | |||||||||||
| ($ Thousands, unless otherwise noted) | 2025 | 2024 | 2025 | 2024 | ||||||||
| Heavy oil (blended bitumen) and midstream sales | $ | 355,160 | $ | 395,279 | $ | 717,535 | $ | 700,320 | ||||
| Cost of diluent | (147,065 | ) | (148,166 | ) | (299,197 | ) | (282,026 | ) | ||||
| Total bitumen and midstream sales | 208,095 | 247,113 | 418,338 | 418,294 | ||||||||
| Royalties | (9,431 | ) | (28,823 | ) | (25,395 | ) | (40,360 | ) | ||||
| Operating expenses – non-energy | (26,810 | ) | (24,417 | ) | (51,697 | ) | (47,542 | ) | ||||
| Operating expenses – energy | (13,621 | ) | (11,635 | ) | (27,128 | ) | (28,193 | ) | ||||
| Transportation and marketing(1) | (22,430 | ) | (20,544 | ) | (42,999 | ) | (40,056 | ) | ||||
| ATHABASCA (THERMAL OIL) OPERATING INCOME | $ | 135,803 | $ | 161,694 | $ | 271,119 | $ | 262,143 | ||||
| (1) Transportation and marketing excludes non-cash costs of $0.6 million and $1.1 million for the three and six months ended June 30, 2025 (three and six months ended June 30, 2024 – $0.6 million and $1.1 million). | ||||||||||||
Corporate Consolidated Operating Income and Corporate Consolidated Operating Income Net of Realized Hedging and Operating Netbacks
The non-GAAP measures of Corporate Consolidated Operating Income including or excluding realized hedging in this News Release are calculated by adding or subtracting realized gains (losses) on commodity risk management contracts (as applicable), royalties, the cost of diluent blending, operating expenses and cash transportation & marketing expenses from petroleum, natural gas and midstream sales which is the most directly comparable GAAP measure. The Corporate Consolidated Operating Netbacks including or excluding realized hedging per boe are non-GAAP ratios calculated by dividing Corporate Consolidated Operating Income including or excluding hedging by the total sales volumes and are presented on a per boe basis. The Corporate Consolidated Operating Income and Corporate Consolidated Operating Netbacks including or excluding realized hedging measures allow management and others to evaluate the production results from the Company’s Duvernay Energy and Athabasca (Thermal Oil) assets combined together including the impact of realized commodity risk management gains or losses (as applicable).
| Three months ended June 30, | Six months ended June 30, | |||||||||||
| ($ Thousands, unless otherwise noted) | 2025 | 2024 | 2025 | 2024 | ||||||||
| Petroleum, natural gas and midstream sales(1) | $ | 368,686 | $ | 422,028 | $ | 748,680 | $ | 738,607 | ||||
| Royalties | (11,223 | ) | (32,321 | ) | (29,948 | ) | (46,172 | ) | ||||
| Cost of diluent(1) | (147,065 | ) | (148,166 | ) | (299,197 | ) | (282,026 | ) | ||||
| Operating expenses | (45,301 | ) | (40,115 | ) | (87,481 | ) | (83,438 | ) | ||||
| Transportation and marketing(2) | (23,390 | ) | (21,675 | ) | (44,757 | ) | (42,085 | ) | ||||
| Operating Income | 141,707 | 179,751 | 287,297 | 284,886 | ||||||||
| Realized gain (loss) on commodity risk mgmt. contracts | 394 | (1,575 | ) | (1,249 | ) | (130 | ) | |||||
| OPERATING INCOME NET OF REALIZED HEDGING | $ | 142,101 | $ | 178,176 | $ | 286,048 | $ | 284,756 | ||||
| (1) Non-GAAP measure includes intercompany NGLs (i.e. condensate) sold by the Duvernay Energy segment to the Athabasca (Thermal Oil) segment for use as diluent that is eliminated on consolidation. | ||||||||||||
| (2) Transportation and marketing excludes non-cash costs of $0.6 million and $1.1 million for the three and six months ended June 30, 2025 (three and six months ended June 30, 2024 – $0.6 million and $1.1 million). | ||||||||||||
Cash Transportation and Marketing Expense
The Cash Transportation and Marketing Expense financial measures contained in this News Release are calculated by subtracting the non-cash transportation and marketing expense as reported in the Consolidated Statement of Cash Flows from the transportation and marketing expense as reported in the Consolidated Statement of Income (Loss) and are considered to be non-GAAP financial measures.
Net Cash
Net Cash is defined as the face value of term debt, plus accounts payable and accrued liabilities, plus current portion of provisions and other liabilities plus income tax payable less current assets, excluding risk management contracts.
Liquidity
Liquidity is defined as cash and cash equivalents plus available credit capacity.
Production volumes details
| Three months ended June 30, | Six months ended June 30, | ||||||||||||
| Production | 2025 | 2024 | 2025 | 2024 | |||||||||
| Duvernay Energy: | |||||||||||||
| Oil and condensate NGLs(1) | bbl/d | 1,608 | 2,806 | 1,723 | 2,006 | ||||||||
| Other NGLs | bbl/d | 282 | 266 | 304 | 223 | ||||||||
| Natural gas(2) | mcf/d | 4,329 | 4,706 | 4,585 | 3,998 | ||||||||
| Total Duvernay Energy | boe/d | 2,612 | 3,856 | 2,791 | 2,895 | ||||||||
| Total Thermal Oil bitumen | bbl/d | 36,476 | 33,765 | 35,613 | 32,651 | ||||||||
| Total Company production | boe/d | 39,088 | 37,621 | 38,404 | 35,546 | ||||||||
| (1) Comprised of 99% or greater of tight oil, with the remaining being light and medium crude oil. (2) Comprised of 99% or greater of shale gas, with the remaining being conventional natural gas. | |||||||||||||
This News Release also makes reference to Athabasca’s forecasted average daily Thermal Oil production of 33,500 ‐ 35,500 bbl/d for 2025. Athabasca expects that 100% of that production will be comprised of bitumen. Duvernay Energy’s forecasted total average daily production of ~4,000 boe/d for 2025 is expected to be comprised of approximately 65% tight oil, 25% shale gas and 10% NGLs.
Liquids is defined as bitumen, light crude oil, medium crude oil and natural gas liquids.
Break Even is an operating metric that calculates the US$WTI oil price required to fund operating costs (Operating Break-even), sustaining capital (Sustaining Break-even), or growth capital (Total Capital) within Adjusted Funds Flow.
